Magnetic resonance method for characterizing fluid samples withdrawn from subsurface earth formations

ABSTRACT

Nuclear magnetic resonance techniques are used in a fluid sampling tool that extracts a fluid from subsurface earth formations into a flow channel within the tool. The magnetic resonance techniques involve applying a static magnetic field and an oscillating magnetic field to the fluid in the flow channel, and magnetic resonance signals are detected from the fluid and analyzed to extract information about the fluid such as composition, viscosity, etc.

The present application is a continuation-in-part of U.S. applicationSer. No. 09/133,234, filed on Aug. 13, 1998, now U.S. Pat. No.6,346,813, which is incorporated herein in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to well logging tools and methods, andmore particularly to methods for analyzing extracted formation fluids bynuclear magnetic resonance (NMR) techniques.

2. Background Information

Downhole formation fluid sampling tools, such as the SchlumbergerModular Formation Dynamics Tester (MDT), withdraw samples of fluids fromearth formations for subsequent analyses. These analyses are needed tocharacterize physical properties such as water and oil volume fractions,oil viscosity, and water salinity, among others. This knowledge isneeded to interpret wireline well logs, and to plan for the efficientexploitation of the reservoir.

In an undisturbed reservoir, formation fluids sometimes partiallysupport the overburden pressure of the earth. When a fluid-bearingformation is penetrated by drilling, formation fluids will flow into theborehole if it is at a lower pressure. The uncontrolled escape ofcombustible hydrocarbons to the surface (“blowout”) is extremelydangerous, so oil wells typically are drilled under pressure. Duringdrilling, fluid (“mud”) is circulated through the well to carry rockchips to the surface. The mud is densified with heavy minerals such asbarite (barium sulfate, 4.5 g/cm³) to ensure that borehole pressure ishigher than formation pressure. Consequently, fluid is forced into theformation from the borehole (“invasion”). Usually particles areprevented from entering the formation by the filtering action of theporous rock. Indeed, the filtration process is self-limiting becausesolids, purposely mixed in the drilling fluid, form a filter cake (“mudcake”) at the surface of the borehole. Nonetheless liquid (“mudfiltrate”) can penetrate quite deeply—as much as several meters into theformation. The filtrate can be either water with various soluble ions,or oil, depending on the type of mud used by the driller. Therefore, thefluid samples withdrawn are mixtures of native formation fluids(including gas, oil and/or water) and the filtrate of mud that was usedto drill the well.

Sample contamination of formation fluids by mud filtrate is universallyregarded as the most serious problem associated with downhole fluidsampling. It is essential that formation fluid, not mud filtrate, iscollected in the sample chambers of the tool. Therefore fluid from theformation is pumped through the tool and into the borehole until it isbelieved contamination has been reduced to an acceptable level. Thus itis necessary to detect mud filtrate in the fluid sample, to decide whento stop pumping the fluid through the tool and to start collecting itfor analysis.

Several measurements are routinely made in fluid sampling tools todetect mud filtrate contamination:

Resistivity indicates the presence of water. The measurement uses thelow frequency electrode technique. Unless there is a continuousconducting path between the electrodes, there is no sensitivity to thepresence of water. Even with a conducting path, the method is unable toseparate the effects of water volume, salinity, and flow geometry. Themeasurement is simple and often useful, but inherently non-quantitative.

Dielectric constant can distinguish oil from water, but not one oil fromanother. Moreover the dielectric constant measurement depends on theflow regime of oil/water mixtures.

Flow line pressure and temperature provide no information on fluidproperties.

Optical Fluid Analyzers (e.g. Schlumberger OFA) can detect contaminationin many cases. It is particularly effective when the mud filtrate isaqueous and the flowing formation fluid is pure hydrocarbon, since thereis a large contrast between water and oil in the near infrared band.However, it does less well when the filtrate is oil based, or when theformation fluid is a mixture of oil and water.

Thus, no presently deployed system is generally useful for determiningthe contamination level of sampled formation fluids. There is a clearneed for an apparatus and method which monitors contamination while thesample is being taken, and indicates when contamination has been reducedto an acceptably low level.

Downhole formation fluid sampling tools can withdraw samples of fluidsfrom earth formations and transport them to the surface. The samples aresent to fluid analysis laboratories for analysis of composition andphysical properties. There are many inefficiencies inherent in thisprocess.

Only about six samples can be collected on each descent (“trip”) of thetool into the borehole. Because fluid sampling tools are deployed fromdrilling rigs, and because the rental charge for such rigs can exceed$150,000 per day in the areas where fluid sampling is most oftenconducted, economic considerations usually preclude multiple trips inthe hole. Thus, oil producing formations are almost always undersampled.

The samples undergo reversible and irreversible changes as a result ofthe temperature and/or pressure changes while being brought to thesurface, and as a result of the transportation process. For example,gases come out of solution, waxes precipitate, and asphalteneschemically recombine. Irreversible changes eliminate the possibility ofever determining actual in situ fluid properties. Reversible changes aredeleterious because they occur slowly and therefore impact samplehandling and measurement efficiency.

The transportation and handling of fluids uphole entails all the dangersassociated with the handling of volatile and flammable fluids at highpressure and temperature. After analyses are complete, the samples mustbe disposed of in an environmentally acceptable manner, with associatedfinancial and regulatory burdens.

Because fluid analysis laboratories are frequently distant from the wellsite, there are substantial delays—often several weeks—in obtainingresults. If a sample is for some reason corrupted or lost duringsampling, transportation, or measurement, there is no possibility ofreturning to the well to replace it.

Thus there is a clear need for immediate analysis of fluid samples atformation temperature and pressure within the downhole sampling tool.

SUMMARY OF THE INVENTION

Nuclear magnetic resonance (NMR) can be used to monitor contaminationand analyze fluid samples in fluid sampling tools under downholeconditions. Measurements are performed in the flow line itself. Themethods are inherently noninvasive and noncontacting. Since magneticresonance measurements are volumetric averages, they are insensitive toflow regime, bubble size, and identity of the continuous phase. Nuclearmagnetic resonance of hydrogen nuclei (protons) is preferred because ofthe ubiquity and good NMR characteristics of this nuclear species.However, magnetic resonance of other nuclear species is useful and soincluded within the scope of the present invention.

In general, the methods of analyzing a fluid according to the inventioninclude introducing a fluid sampling tool into a well bore thattraverses an earth formation. The fluid sampling tool extracts the fluidfrom the earth formation into a flow channel within the tool. While thefluid is in the flow channel, a static magnetic field is applied, and anoscillating magnetic field applied. Magnetic resonance signals aredetected from the fluid and analyzed to extract information about thefluid.

These and other features of the invention are described in more detailin figures and in the description below.

BRIEF DESCRIPTION OF THE DRAWINGS

A complete understanding of the present invention may be obtained byreference to the accompanying drawings, when considered in conjunctionwith the subsequent detailed description, in which:

FIG. 1 illustrates a schematic diagram of one embodiment of a fluidsampling tool utilized in extracting formation fluid in accordance withthe invention;

FIG. 2 shows a schematic axial section of a flow line NMR apparatus thatcan be utilized in the sampling tool depicted in FIG. 1;

FIG. 3 shows a schematic cross sectional view of one embodiment of aflow line apparatus depicted in FIG. 2;

FIG. 4 depicts a flow chart of one embodiment of a method of thisinvention;

FIG. 5 depicts a graph showing the logarithmic mean T₂ plotted versusviscosity for crude oils;

FIG. 6 shows T₂ distributions for a number of crude oils having avariety of physical properties; and

FIG. 7 shows a fluid correlation chart that relates stock tank APIgravity, viscosity, gas-oil ratio and fluid temperature.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

Apparatus

Modern fluid sampling tools, such as Schlumberger's Modular DynamicsTesting Tool (MDT) are composed of several parts which enable extractionof fluids from permeable earth formations. Referring to FIG. 1, with thetool identified by 10, the following modules are in the prior art[Schlumberger Wireline Formation Testing and Sampling, SMP-7058 (1996),published by Schlumberger Wireline and Testing]: the electric powermodule 11 and the hydraulic power module 12 power the tool; the probemodule 13 is deployed so as to make a hydraulic seal with the formation;and the pumpout module 17 lowers the pressure in the flow line in acontrolled manner so as to extract fluid from the formation whilemaintaining the pressure near the original formation pressure. Samplesare optionally monitored by an optical fluid analyzer (OFA) 14 and areretained for transportation to surface laboratories in the multisamplemodule 16.

The NMR module which is the subject of this invention is shown at 15 inFIG. 1. It is built around the flow line, and provides no obstructionsto the flow of fluid within the tool.

More detailed drawings of the NMR apparatus 15 are shown in FIGS. 2 and3. Fluid withdrawn from the formation flows through a flow channel 21.In non-instrumented sections of the tool, the channel is defined by athick-wall metal tube 24 capable of withstanding formation pressure ofat least 20,000 pounds per square inch.

In the NMR-instrumented section of the flow line, the channel is definedby the inside diameter of an antenna support 22. The antenna supportmust be made of a nonconductive and preferably nonmagnetic material. Theantenna support must be capable of resisting chemical attack byformation fluids. It must also be capable of resisting erosion by solidswhich may enter the flow line from the formation or borehole. Ceramicsor hard polymeric materials are suitable materials for the antennasupport.

The NMR antenna 23 is embedded in the antenna support. The NMR antennamust be capable of radiating magnetic field at the Larmor frequency (seebelow), typically 40 MHz. This radiated magnetic field is conventionallycalled B₁. In one illustrative implementation, the NMR antenna is asolenoidal coil which generates an oscillating magnetic field parallelto the axis of the flow channel. The B₁ field need not be particularlyuniform over the volume of the flow channel.

The antenna support is enclosed by an enlarged portion of thick-wallmetal tube 24, so as not to obstruct the flow channel 21. The tube 24and antenna support 22 are able to contain the high pressure formationfluids in the flow channel. High frequency magnetic fields cannotpenetrate metals, so the NMR antenna must be placed inside the metaltube of the flow line.

An array of permanent magnets 25 is placed outside the thick-wall metaltube. These create a constant magnetic field, conventionally calledB_(O), substantially perpendicular to the B₁ field generated by theantenna. To make chemical shift measurements (see below) B_(O) ispreferably substantially uniform in the volume occupied by fluid.However, to measure relaxation time, diffusion coefficient, or spindensity of hydrogen or other elements, B_(O) need not be particularlyuniform. One suitable arrangement of permanent magnets is described byHalbach [K. Halbach, Nuc. Inst. Methods 169, 1-10 (1980); K. Halbach,Nuc. Inst. Methods 187, 109-117 (1981)].

The entire NMR apparatus is enclosed in a sonde housing 26 which isattached to other similar housings in the tool string lowered into thewell.

Gradient coils (not shown) can also be provided for the purpose ofmaking pulsed field gradient measurements of diffusion coefficient andother quantities. If the static magnetic field is aligned with thez-axis, the most effective gradients are dB_(z)/dx, dB_(z)/dy, anddB_(z)/dz. A dB_(z)/dz gradient can be generated by a pair of saddlecoils potted together with the coil which provides the B₁ field.Prescriptions for designing saddle coils that generate maximally uniformgradients can be found in the literature [R. Turner, “Gradient CoilSystems”, Encyclopedia of Nuclear Magnetic Resonance, 1996].

NMR Technique

The techniques of nuclear magnetic resonance are well documented in theliterature [E. Fukushima and S. B. W. Roeder, “NMR, A Nuts and BoltsApproach”, Addison-Wesley (1981); T. C. Farrar and E. D. Becker, “Pulseand Fourier Transform NMR”, Academic Press (1971)]. The static B_(o) andoscillating B₁ magnetic fields should be substantially perpendicular toeach other. The B₁ antenna should be capable of transmitting andreceiving signals at the Larmor frequency f,

f=(γ/2π)B_(o)  (1)

where γ is the gyromagnetic ratio of the nuclear species of interest,and Bo is the strength of the static magnetic field. For hydrogennuclei, (γ/2π)=4258 Hz/Gauss. For values of the gyromagnetic ratio ofother nuclei, see e.g. CRC Handbook of Chemistry and Physics [CRCPress], and the Table hereinbelow. Resonating nuclei other than ¹H isaccomplished by changing the frequency of operation to match the Larmorfrequency of the nucleus of interest.

Before quantitative NMR measurements can be made on a fluid sample, ittypically must be exposed to the static magnetic field Bo for asubstantial time. The longer the exposure before the measurement begins,the more complete the alignment of nuclear moments by Bo. The degree ofalignment, also called polarization, is given by

P=Po(1−exp(−t/T ₁))  (2)

In this equation, t is the time that the nuclei are exposed to Bo beforethe application of the B₁ field, T₁ is a time constant characteristic ofthe material, called the longitudinal relaxation time, P is the degreeof polarization, and Po is the degree of polarization in the limit thatt goes to infinity. For an explanation of NMR relaxation times, see R.L. Kleinberg and H. J. Vinegar, “NMR Properties of Reservoir Fluids”,Log Analyst November-December 1996, pg 20-32. For oil field fluids, T₁can range from a few milliseconds (very viscous crude oils) to 10seconds (very low viscosity crude oils with dissolved gas).

All standard NMR measurements can be made using the apparatus described.These include measurements of spin density (proportional to NMR signalamplitude), longitudinal and transverse relaxation times T₁ and T₂ and,more generally, their distributions [R. L. Kleinberg, “Well Logging”,Encyclopedia of Nuclear Magnetic Resonance, volume 8 pg 4960-4969, JohnWiley & Sons, 1996]; diffusion coefficient and other q-spacemeasurements [P. Callaghan, “Principles of Nuclear Magnetic ResonanceMicroscopy”, Clarendon Press, 1991]; flow velocity measurements [A.Caprihan and E. Fukushima, “Flow Measurements by NMR”, Physics Reports,198, 195-235 (1990)]; and chemical shift spectroscopy when the B. fieldis sufficiently uniform [H. J. Vinegar “Method of DeterminingPreselected Properties of a Crude Oil”, U.S. Pat. No. 5,306,640 (1994)].

One particularly useful NMR pulse sequence is theCarr-Purcell-Meiboom-Gill (“CPMG”) pulse sequence, and itsgeneralization, the Fast Inversion Recovery-CPMG pulse sequence[Kleinberg et al, U.S. Pat. No. 5,023,551]. Many other pulse sequencesare in common use, as cited in '551, and in the above book references.

Speed Effects

During pumpout, fluid may be moving at a high rate of speed through theflow line NMR apparatus. This limits polarization time and signalacquisition time, so some types of quantitative measurements may not bepossible. However, there are a number of methods by which contaminationcan be monitored qualitatively and some by which fluid may be analyzedquantitatively during pumpout.

The rate that fluid moves through the tool depends on the permeabilityof the earth formation, the viscosity of the fluid, and the rate atwhich fluid can be pumped through the tool. For example, in theSchliumberger MDT, the flow control module allows flows in the range1-500 cm³/s, while the pumpout module operates at speeds up to about 40cm³/s. [“Schlumberger Wireline Formation Testing and Sampling” (1996)pg. 4-29, 4-40]. The flow line has an inside diameter of about 0.5 cm,so 500 cm³/s corresponds to a flow speed of about 25.5 m/s while 40cm³/s corresponds to a flow speed of about 2 m/s. The effect of flow issimilar to the speed effect of the Schlumberger CMR [J. M. Singer, L.Johnston, R. L. Kleinberg, and C. Flaum, “Fast NMR Logging for BoundFluid and Permeability”, SPWLA 38th Annual Logging Symposium, 1997,Paper YY, Section 3].

Quantitative NMR measurements typically require that the spins be fullypolarized by the static magnetic field prior to data acquisition. Thisrequires that the spins be exposed to Bo for three to five times as longas the longitudinal relaxation time T₁. For water or light oils at hightemperature, T₁ can be several seconds; thus wait times of 10 seconds ormore will be required. Since the NMR apparatus is typically 0.3 m long,even moderate flow speeds prevent most quantitative measurements frombeing made during pumpout. However, some quantitative measurements onflowing fluids, such as downhole viscosity and water composition, arestill possible. Also, qualitative measurements to detect contaminationcan be made during pumpout. When contamination is at a sufficiently lowlevel, pumping can be stopped or slowed and the full range ofquantitative measurements can be made (see below). Alternatively, thesestatic quantitative measurements can be made while still pumping bydiverting the flow around the sample chamber.

Measurement Overview

A typical measurement sequence is shown in FIG. 4. Fluid is admittedinto the tool flow line 41 and a measurement procedure initiated 42. Anindication of magnetic resonance, of a group described below, ismeasured and recorded 43. While the indication changes with time, themeasurement loop is continued 44; when the indication stabilizes 45,contamination has been reduced to a minimum. Alternatively,contamination in the fluid may be monitored by optical measurements ofthe fluid, as described, for example, in U.S. Pat. No. 6,274,865 toSchroer and Mullins. Then the flow is stopped or slowed 46 andquantitative analysis is undertaken 47. At the conclusion of thequantitative analysis, the fluid in the flow line is routed to storagebottles, or is expelled to the borehole. Alternatively, as mentionedabove, some quantitative measurements may be made on the fluid withoutstopping or slowing its flow in the flow line, or a quantitativeanalysis may be made on a static fluid sample while diverting flowaround the sample chamber.

There are a wide variety of measurements that can be used to monitorcontamination, and another broad group of measurements that are usefulin quantitatively analyzing fluid properties. Some of these aredescribed below.

Contamination Monitoring Methods Using Flow Line NMR

Oil Base Mud Filtrate vs. Formation Oil

Many wells are drilled with muds in which oil is the continuous phase.These muds are comprised of hydrocarbons (“base oil”), typicallyhexadecanes, plus salt water, solids, and chemical additives. Usuallyonly the base oil, together with oil-soluble additives, enter theformation and mix with formation oils. Water and solids remain in theborehole, or form a filter cake on the borehole wall. The oil enteringthe formation is called “oil base mud filtrate”.

There are a number of NMR-detectable contrasts between oil base mud(OBM) filtrates and formation oils: (1) viscosity, (2) composition, (3)trace element content (natural or introduced), (4) diffusioncoefficient, (5) proton density, and (6) molecular conformation.

Viscosity: Extensive measurements on pure substances and crude oils havefound an excellent correlation between fluid viscosity and the NMRrelaxation times T₁ and T₂ [Bloembergen et al “Relaxation Effects inNuclear Magnetic Resonance Absorption”, Physical Review 73, 679-712(1948); Morriss et al “hydrocarbon Saturation and Viscosity Estimationfrom NMR Logging in the Belridge Diatomite”, Log Analyst, March-April1997, pg 44-59]. Morriss et al suggest that the logarithmic mean valueof the relaxation time is strongly correlated with viscosity, see FIG.5. Other relaxation time measures are also useful in qualitativelymonitoring viscosity, including the time it takes for the NMR amplitudeto fall to 1/e of its initial value.

In general, the viscosity of OBM filtrate is different (higher or lower)than that of the formation oil. Thus measurements of NMR relaxation timecan distinguish these fluids from one another. Moreover, when OBMfiltrate is mixed with formation oil, the viscosity, and thereforerelaxation time, of the mixture will be intermediate between theviscosities of the individual components.

As draw down continues, the time dependence of viscosity of the oilphase in the flow stream, η(t), will vary as

η(t)=η_(mf)+[(η_(n)−η_(mf))f(t)]  (3)

where η_(mf) is the viscosity of the mud filtrate under downholeconditions, which can be measured in advance in a laboratory if desired,and η_(n) in is the unknown viscosity of the native oil. f(t) depends onfluid and formation properties and is therefore unknown. However, f(t)is expected to be subject to the conditions that f(0) ≧0, df/dt>0,d²f/dt²<0 (at least at long time), and f(∞)=1. Given a sufficiently longacquisition of data, η_(n) can be estimated from the long-time asymptoteof η(t), and contamination level at any given time can be estimated.

Relaxation Time Distribution: Oil base mud filtrates are characterizedby a narrow distribution of relaxation times. In contrast, crude oilshave broad distributions of relaxation times, see FIG. 6 [Morriss et al,“Hydrocarbon Saturation and Viscosity Estimation from NMR Logging in theBelridge Diatomite”, Log Analyst, March-April 1997, pg 44-59]. Thus evenif the OBM filtrate and native crude have the same viscosity, NMR T₁and/or T₂ analysis can distinguish them based on the width of thedistribution of relaxation times.

Trace Element Content: Trace elements can be detected in two ways. (1)Paramagnetic ions or compounds dissolved in liquids shorten the NMRrelaxation times of liquid protons. (2) The quantity of certain othernuclear or electronic species can be measured directly by resonancemeasurements of those species.

Dissolved paramagnetic compounds will reduce the proton relaxation timesof oils. Thus if two oils have the same viscosity, they will havedifferent relaxation times if they have substantially differentparamagnetic content. While many crude oils and most oil base mudfiltrates have negligible magnetic content, some crude oils havesignificant amounts of vanadium or nickel [Tissot and Welte, “PetroleumFormation and Occurrence”, Springer-Verlag, 1978, FIG. IV. 1.20].Because the relaxation effect is proportional to paramagneticconcentration, the proportions of two oils in a mixture can bemonitored. Deliberate introduction of an oil-soluble paramagneticsubstance into the oil base mud can considerably enhance this effectwhen the native crude is relatively free of paramagnetic material.

NMR-active nuclei can be monitored directly to determine contaminationlevels. OBM filtrates may differ from native oils by havingsubstantially different concentrations of oxygen, sulfur, or nitrogen.Of these, nitrogen is the best NMR target because its NMR-active form,¹⁴N, has good NMR sensitivity and a reasonable natural abundance, seeTable 3 below. Considerably greater sensitivity to contamination can beattained if trace elements are mixed with the drilling mud to mark thefiltrate. For example, a fluorine-labeled organic compound can bedetected directly by measuring the ¹⁹F resonance.

Diffusion Coefficient: The diffusion coefficient is closely related tothe viscosity; they are related by the approximate relation [J. C. M.Li, P. Chang, “Self Diffusion Coefficient and Viscosity in Liquids”, J.Chem. Phys. 23, 518-520 (1955)] $\begin{matrix}{{D\quad \eta} = {c\quad k\quad {T\left( \frac{N}{V} \right)}^{1/3}}} & (4)\end{matrix}$

where D is the diffusion coefficient, η is the viscosity, c is anempirical constant, k is Boltzmann's constant, T is the absolutetemperature, and (N/V) is the number of molecules per unit volume. Thusin many cases, measurements of T₂ and diffusion coefficient areduplicative. However, T₂ is influenced by the presence of paramagneticspecies, whereas the diffusion coefficient is not. Thus diffusionmeasurements, which can be made, for example, using CPMG sequenceshaving different echo spacings and in the presence of a magnetic fieldgradient (see eqns (8) and (9), below), can be independently useful indetermining contamination levels.

NMR Amplitude: Speed effects play an important role in the measurementof NMR amplitude, by reducing the time that the nuclear spins areexposed to the polarizing field B_(o). Hydrogen NMR amplitude iscontrolled by hydrogen index and the effect of incomplete polarization:

S=V _(water) ×HI _(water)×[1−exp(−W/T _(1water))]+V _(oil) ×HI_(oil)×[1−exp(−W/T _(1oil))]+V _(gas) ×HI _(gas)×[1−exp(−W/T_(1gas))]  (5)

V_(water), V_(oil), and V_(gas) are the relative volumes of water, oil,and gas in the NMR measurement section of the flow line. HI is thehydrogen index (proton density relative to pure water). W is theeffective polarization time of the measurement, which is a function of avariety of parameters, including the wait time between pulse sequences,the flow rate of the fluid, the distance the fluid traveled throughB_(o), and the distance the fluid traveled through B₁.

Oils with API gravity greater than 20, and with no dissolved gas, haveproton density equal to that of water [Vinegar et al, “Whole CoreAnalysis by ¹³C NMR”, SPE Formation Evaluation 6, 183-189 (June 1991)].Most oil mud filtrates also have hydrogen densities equal to that ofwater. Gas is always a formation fluid; it is never a part of mudfiltrates. A reduced proton density indicates gas, which isanticorrelated with the presence of mud filtrate in the flow line.

Medium-to-Heavy Oil/Oil Base Mud Filtrate: Medium to heavy oils haveshort T₁, and are substantially polarized in the flow stream. Oil basemud filtrates have T₁'s in the range of several hundred milliseconds,and thus are not completely polarized in a rapidly moving stream. As theratio of heavier formation oil increases, signal amplitude increases.

Light Oil and Gas/Oil Base Mud Filtrate: This is the most importantcontamination detection problem, and the one the optical fluid analyzerhas the most trouble with. In this case, native oil has a longerrelaxation time than OBM filtrate. Thus as the proportion of nativefluid increases, the proton signal amplitude will decrease. The presenceof free gas associated with native oil accentuates the contrast. Signallevel will stabilize at a low level when OBM contamination has beeneliminated.

Spectroscopy: In ordinary laboratory practice, NMR spectroscopy can beused to distinguish families of hydrocarbons from each other. Forexample, protons in aromatic (ring) compounds such as benzene andnaphthalene, have slightly different resonant frequency than protons inalkanes [H. J. Vinegar “Method of Determining Preselected Properties ofa Crude Oil”, U.S. Pat. No. 5,306,640 (1994)]. OBM filtrates can bedistinguished from formation oils when they have distinctive molecularconformations. Monitoring the spectrum during pumpout providesfluid-selective information. For example, T₁ changes in the oil phasecan be monitored independent of the signal from water. Incompletepolarization and hydrogen index effects reduce the amplitudes ofindividual spectral lines. The effects are the same as those affectingthe amplitude measurement Unlike the other techniques discussed,spectroscopy requires very good uniformity of the static magnetic fieldof the NMR apparatus: typically 1 part per million or better over thesample volume.

Water Base Filtrate vs. Formation Water

Trace Element Content: NMR measurements can also help distinguish waterbase mud (WBM) filtrate from formation water. There will be little or nocontrast in viscosity, diffusion coefficient, proton density, ormolecular conformation. However, the trace element content can beconsiderably different Water soluble paramagnetic ions (either naturalof introduced) will have a strong relaxing effect, which can be used tomonitor proportions of filtrate and connate water.

The use of chromium lignosulfonate muds, or manganese tracers used forformation evaluation [Horkowitz et al, 1995 SPWLA Paper Q], addparamagnetic ions to the filtrate. These ions reduce the filtraterelaxation time. Thus they increase contrast with light oils and gas,and decrease contrast with medium to heavy oils.

Paramagnetic ion can also be introduced in the flow line. 2×10¹⁸ions/cm³ of Fe³⁺ will reduce water T₁ to 30 msec [Andrew, NuclearMagnetic Resonance (1955)]. This is equivalent to 54 grams FeCl₃ per 100liters of water. For flow line doping to work, the water must be thecontinuous phase, and come into contact with the source of ions.

NMR is sensitive to sodium, so if filtrate and connate water havedifferent salinity, sodium concentration provides a good measure ofcontamination. The flow line apparatus described can make NMRmeasurements of sodium by retuning the antenna to the appropriateresonance frequency. Sodium longitudinal relaxation time is 47 ms at 2MHz and room conditions. Thus the amplitude of the sodium resonance canbe measured at least semi-quantitatively during flow.

Potassium is particularly interesting because of its large concentrationin KCl muds. Monitoring potassium NMR amplitude is a direct measure ofcontamination when KCl mud has been used. The longitudinal relaxationtime of potassium in aqueous solution is 38 msec [Decter, Progress inInorganic Chemistry 29, 285 (1982)] so speed effect is minor.

Oil vs. Water

Oil and water can be distinguished by many of the same techniquesoutlined above. Proton relaxation time differences may be based onviscosity, diffusion coefficient, paramagnetic relaxation agents, orNMR-visible trace elements. The water phase will have a very narrowrelaxation time distribution in contrast to crude oil, which often has abroad distribution. Salt water has a large sodium and/or potassium NMRsignal which will be absent in the oil phase. Sodium detection, inparticular, offers a good way of monitoring water contamination of oilsamples, even in the presence of gas. Chemical shift spectroscopy canseparate oil and water resonances.

NMR Amplitude: Medium-to-Heavy Oil/Water Base Mud Filtrate: The moreviscous the oil, the more completely it will be polarized, becauseviscous oils relax quickly and flow slowly (at least in some flowregimes). In contrast, the viscosity of produced water is less than 1centipoise, and frequently has a long relaxation time T₁. Thus the oilwill be fully polarized and the water will not. As contamination isreduced, the signal gets bigger.

Light Oil and Gas/Water Base Mud Filtrate: Water-based mud filtratesoften have relaxation times intermediate between oil-based mud filtratesand native oils, thus the contrast in hydrogen signal amplitude issomewhat reduced as compared to oil/oil-based mud filtrate. However,hydrogen amplitude can still be used to monitor water-based mud filtratecontamination, especially in the presence of formation gas whichdepresses the total signal as water contamination diminishes.

Quantitative Fluid Characterization with NMR

A downhole NMR instrument installed in fluid sampling tools can makesome of the most important measurements now being made in fluid analysislaboratories. The purpose of the downhole measurements is to providemeans of making a partial analysis when the sample is taken, after whichthe sample can be saved for further analysis or discarded to theborehole. In this manner an unlimited number of fluid samples can beanalyzed on each trip in the hole. The measurements are made atformation temperature and pressure, after minimum manipulation, thushelping to ensure sample integrity. Transportation and disposal problemsare minimized or eliminated.

Nuclear magnetic resonance (NMR) is a powerful fluid characterizationtechnique. The volumes of individual components of fluid mixtures, andsome physical properties of each component, can be measured. The methodis inherently noninvasive and noncontacting. Since NMR measurements arevolumetric averages, they are insensitive to flow regime, bubble size,and identity of the continuous phase.

The physical properties of formation fluid are determined quantitativelyby making a measurement when it has been determined that contaminationis reduced to an acceptable level. Alternatively, fluids can becharacterized by measuring their physical properties during mud filtrateclean up, and extrapolating the results to zero contamination level.

Nuclear magnetic resonance of ¹H (protons) is preferred because of theubiquity and good NMR characteristics of this nuclear species. However,magnetic resonance of other nuclear species are useful and can beperformed by the same apparatus, as detailed below. The apparatus andtechnique are the same as described above.

Volume Fractions

The calibrated NMR signal from a mixture of gas, oil, and water is

S=V _(water) ×HI _(water) ×[1 −exp(−W/T _(1water))]+V _(oil) ×HI_(oil)×[1−exp(−W/T _(1oil))]+V _(gas) ×HI _(gas)×[1−exp(−W/T_(1gas))]  (6).

V_(water), V_(oil) and V_(gas) are proportional to the volumes of eachfluid. HI (hydrogen index) is the proton density for each fluid,normalized to the proton density of water at 20° C. and 1 atmospherepressure. The last factor on each line is a correction to account forpolarization time W. When the NMR measurement is taken on a flowingfluid, polarization may not be complete, and the effective polarizationtime W would be a function of various parameters, such as the wait timebetween pulse sequences, the flow rate of the fluid, the distance thefluid traveled through B_(o), and the distance the fluid traveledthrough B₁.

Water, oil, and gas signals can be separated by methods described below.To obtain the fluid volumes from resolved NMR signals, the hydrogenindex must be determined. The situation is different for each fluid. Forcharts of hydrogen index, see R. L. Kleinberg, H. J. Vinegar, LogAnalyst, November-December 1996, pg. 20-32.

Water: HI_(water) is defined to be unity at room temperature andpressure; the effects of elevated temperature and pressure are tabulated[Amyx, Bass and Whiting, Petroleum Reservoir Engineering, 1960, pg 458].A larger correction to HI_(water) is due to salinity. Thus the saltcontent of the water must be known to obtain an accurate volume. Thesolubility of natural gas in water is low, and therefore does not have asignificant effect on hydrogen index.

Oil: For oil at room temperature and pressure, without dissolved gas,hydrogen index is unity for API gravity greater than 20 [H. J. Vinegaret al, “Whole Core Analysis by 13C NMR”, SPE Formation Evaluation, 6,183-189 (1991)], which is the range of interest for fluid samplingtools. HI_(oil) will track density as a function of temperature andpressure. There is no generally accepted correlation between HI_(oil)and dissolved gas content.

Gas: HI_(gas) is in the range of 0-0.6 for oilfield conditions, so thegas signal is not negligible. HI_(gas) is a known function oftemperature and pressure, which are measured by fluid sampling tools,and chemical composition, which is not. Carbon dioxide has no proton NMRsignal, and thus may be obtained by difference when the volumes ofwater, oil, and natural gas are measured directly. At high flow rates,however, gas will not polarize significantly and will provide minimalNMR signal. One may then use an independent density measurement such asx-ray to determine the presence of gas.

Relaxation Time Analysis

Water and Oil in the Absence of Gas: Water in the tool flow line atdownhole temperature and pressure will have relaxation times of severalseconds. The magnetization decay of crude oils is multiexponential, butwhen the downhole viscosity of oil is greater than a few centipoise,water and oil NMR signals have distinctly different relaxation times [R.L. Kleinberg, H. J. Vinegar, Log Analyst, November-December 1996, pg.20-32.]. This enables oil and water signals to be separated using a T₁or T₂ distribution, as is familiar from NMR formation evaluation [R. L.Kleinberg and C. Flaum, “Review: NMR Detection and Characterization ofHydrocarbons in Subsurface Earth Formations”, in “Spatially ResolvedMagnetic Resonance: Methods and Applications in Materials Science,Agriculture and Biomedicine”, B. Blumich, et al eds, 1998]. If the waterand oil signals are well resolved in the T₁ or T₂ distribution, in theabsence of free gas, the areas under the peaks are equal to

V _(water) ×HI _(water)×1−exp(−W/T _(1water))]  (7a)

and

V _(oil) ×HI _(oil)×[1−exp(−W/T _(1oil))]  (7b)

respectively, where W is the effective polarization time, as describedpreviously.

The acquisition of a string of echoes via a CPMG sequence allows one todetermine the T₂ of a static sample. Once the time-domain data has beenacquired, existing inversion methods can be used to determine a T₂distribution. T₁=T₂ for liquids in the flow line apparatus, so if T₂ ismeasured by the CPMG pulse sequence, the polarization correction can beaccurately computed.

In the presence of a gradient field, the echo amplitude decay in a CPMGexperiment is given by:

M(t)=M ₀ e ^(−t/T) ^(₂) e ^(−γ) ² ^(G) ² ^(T) ^(_(E)) ² ^(Dt/12)  (8),

where M₀ is the equilibrium magnetization, t is the time after theinitial rf pulse, G is the gradient, and D is the diffusion constant ofthe sample. The echo time, T_(E), is defined as the time between echopeaks, or equivalently, the time between refocusing pulses. Varying theecho time varies the overall decay rate and one may determine both T₂and D.

Gas Measurements: The relaxation time of gas is a function only of itstemperature and pressure, which are measured. For free gas in theabsence of magnetic field gradients, T₁=T₂, in the range of severalseconds, and the decay is single exponential [C. Straley, “AnExperimental Investigation of Methane in Rock Materials”, SPWLA 38thAnnual Logging Symposium, 1997, Paper AA]. Thus the decay time of freegas can coincide with water and light oil. Gas is distinguished fromliquids by its diffusion coefficient. Several methods may be used:

Gas Diffusion-Relaxation Method 1:

(1) The transverse magnetization decay is measured by CPMG in the usualmanner, and the T₂ distribution is determined. Gas relaxes withrelaxation time T2,bulk.

(2) The transverse magnetization decay is measured by CPMG in thepresence of a uniform, steady magnetic field gradient supplied bygradient coils. The relaxation rate of gas is then $\begin{matrix}{\frac{1}{T_{2}} = {\frac{1}{T_{2,{bulk}}} + {\frac{\left( {\gamma \quad G\quad T_{E}} \right)^{2}D}{12}}}} & (9)\end{matrix}$

where γ is the gyromagnetic ratio, G is the applied gradient, T_(E) isthe CPMG echo spacing, and D is the diffusion coefficient Since T₂,bulkand all these parameters are known, the two measurements can be readilyanalyzed for the gas signal.

Gas Diffusion-Relaxation Method 2:

A pulsed field gradient technique can be used, analogous to thatdescribed by Kleinberg, Latour and Sezginer, U.S. patent applicationSer. No. 08/783,778, issued as U.S. Pat. No. 5,796,252 on Aug. 18, 1998,and incorporated herein by reference in its entirety.

Chemical Shift Analysis: Proton NMR chemical shift can also be used todistinguish fluids [H. J. Vinegar, U.S. Pat. No. 5,306,640 (1994)]. Gas,light oil, and water have distinct chemical shifts [Dyer, Applicationsof Absorption Spectroscopy of Organic Compounds (1965) pg. 84-85]:

TMS CH₄ H₃C—C —CH₂— H₂O Shift (ppm) 10 9.77 9.1 8.7 4.7

The chemical shift of methane depends on pressure [Trappeniers andOldenziel, Physica 82A, 581 (1976)], and whether it is in the gas phaseor in solution [Rummens and Mourits, Canadian Journal of Chemistry 55,3021 (1977)].

Fluids are distinguished when the B_(o) measurement field is homogeneousto better than 1 part per million. The areas under the spectral linesare proportional to fluid volumes as described by Eqn (6). Chemicalshift spectroscopy is particularly useful when oil and water havesimilar relaxation times.

Carbon NMR

Carbon may be found in some formation waters, as carbonate orbicarbonate ion, but it predominates in oil and gas. Thus in many cases,a measurement of carbon amplitude gives a direct measurement ofhydrocarbon quantity. The NMR-active isotope of carbon is ¹³C, which hasa natural abundance of about 1%. At natural abundance, ¹³C-NMRvisibility is about 1.75×10⁻⁴ that of ¹H (see Table 3 below). Also, ¹³Crelaxation times tend to be long (T₁ for carbon ranges from hundreds ofmilliseconds to seconds for oils with API gravity greater than 20 orviscosity less than 100 cp), making signal accumulation slow.

Static ¹³C NMR measurements can be made with a CPMG sequence. SuccessiveCPMG scans may be stacked and summed to improve the signal-to-noiseratio (SNR). Summing over each echo in time (or, equivalently, lookingat the dc component of each echo in frequency space) can further improveSNR. Additional SNR improvement may result from inclusion of properfiltering.

With such improvements in SNR, it is estimated that a H/C ratio may bedetermined with an error of about 4.8% in less than 5 minutes.Cross-polarization with hydrogen is expected to give a further reductionin error. [Gerstein and Dybowski, Transient Techniques in NMR of Solids,1985].

Oil Viscosity

Oil viscosity can be determined if the oil signal is resolved from otherfluid signals by either relaxation analysis (see above) or chemicalshift analysis (see above). Also, oil viscosity can be related to theoil's diffusion coefficient, which may be measured using techniquesdescribed previously.

When relaxation analysis is used, T₁ or T₂ is measured directly. Asstated above, crude oils have broad distributions of relaxation times.However, it has been found that oils with low viscosity relax moreslowly than those with higher viscosity [C. E. Morriss, R. Freedman, C.Straley, M. Johnston, H. J. Vinegar, P. N. Tutunjian, in Transactions ofthe SPWLA 35th Annual Logging Symposium, 1994; Log Analyst, March-April1997, pg 44.]. A single relaxation time parameter which captures theviscosity dependence is the logarithmic mean: $\begin{matrix}{T_{2\quad L\quad M} = {\exp\left\lbrack \frac{\sum\limits_{i}{m_{i}{\log_{e}\left( T_{2i} \right)}}}{\sum\limits_{i}m_{i}} \right\rbrack}} & \left( {10a} \right) \\{{T_{1L\quad M} = {\exp\left\lbrack \frac{\sum\limits_{i}{m_{i}{\log_{e}\left( T_{1i} \right)}}}{\sum\limits_{i}m_{i}} \right\rbrack}};} & \left( {10b} \right)\end{matrix}$

see also FIG. 5. It has been found that over the range 1 cp to 300 cp,and in the absence of an applied magnetic field gradient, T_(1LM) andT_(2LM) (in seconds) are related to viscosity η (in centipoise):$\begin{matrix}{{T_{2L\quad M} = \frac{1.2}{\eta^{0.9}}},{{at}\quad 2\quad {MHz}}} & \left( {11a} \right) \\{{T_{1L\quad M} = \frac{1.1}{\eta^{0.5}}},{{at}\quad 85\quad {{MHz}.}}} & \left( {11b} \right)\end{matrix}$

When chemical shift analysis is used, the longitudinal relaxation time,T₁, of each spectral line can be determined by standard methods [H. J.Vinegar U.S. Pat. No. 5,306,640 (1994)]. Then viscosity can be foundfrom Eqns (11a) and (11b) using the fact that T₁=T₂ for crude oils inthe absence of magnetic field gradients.

Relation of oil viscosity, gas-oil. ratio, stock tank API gravity andrelaxation rates: Downhole oil viscosity may be obtained from NMRrelaxation rates with a correction for gas/oil ratio (GOR):$\begin{matrix}{{T_{1L\quad M} = {T_{2L\quad M} = \frac{a\quad T}{\eta_{0}{f\left( {G\quad O\quad R} \right)}}}},} & (12)\end{matrix}$

where T is the absolute temperature, η₀ is the crude oil viscosity atdownhole temperature and pressure, a is an experimentally determinedparameter with a value of 0.004 s·cp·K¹ for a wide variety of crude oilsat 2 MHz, and GOR is defined as m³ solution gas per m³ stock tank liquidat standard conditions (60° F., 1 atm) [R. Freeman, et al, “A New NMRMethod of Fluid Characterization in Reservoir Rocks: ExperimentalConfirmation and Simulation Results”, SPE Annual Technical Conferenceand Exhibition, SPE 63214 (2000)]. The empirically determined f(GOR) isgiven by:

f(GOR)=10¹⁰ ^(α)   (13),

where

α=−0.127(log₁₀(GOR))²+1.25log₁₀(GOR)−2.80  (14).

Alternatively, f(GOR) may be fit to the following polynomial expression:

f(GOR)=1+(3.875×10⁻³)GOR−(5.3736×10⁻⁷)GOR ²   (15).

GOR may be determined, for example, using an optical fluid analyzer,such as Schlumberger's OFA, which can make optical measurements on afluid in the flow line. Near-infrared (NIR) absorptions of methane(CH₁), a principal component of downhole gas, can be distinguished fromthose of methylene (—CH₂—), a dominant component of oil, and the twocorrelated to GOR. [see U.S. Pat. No. 5,939,717 issued Aug. 17, 1999,incorporated herein by reference in its entirety].

Once GOR and downhole viscosity are known, one may also calculate stocktank API gravity. The stock tank (i.e., standard surface condition, 60°F., 1 atm) API gravity (or density) of crude oil is an importantdeterminant of its price, and is therefore of fundamental interest to anoperator in the field. Determining a stock tank property under downholeconditions requires use of fluid property correlations, which arewell-established.

One such correlation relates stock tank API gravity to downhole fluidtemperature (which is typically measured with downhole sampling tools,such as the MDT), GOR, and viscosity. Once downhole viscosity, GOR, andtemperature have been measured, the stock tank API gravity can bedetermined using a fluid correlation chart, such as that shown in FIG. 7[R. L. Kleinberg and H. J. Vinegar, “NMR Properties of ReservoirFluids,” Log Analyst, November-December 1996, p. 28]. The lower verticalaxis of the chart marks viscosity. A horizontal line is extended fromthe viscosity value measured by NMR to a curve associated with the GORdetermined by optical analysis (or other means). From the point at whichthe viscosity value intersects with the GOR curve, a vertical line isextended to the curve associated with the fluid temperature. From thatpoint of intersection with the temperature curve, a second horizontalline is extended to the upper vertical axis, which marks the stock tankAPI gravity value. In practice, these steps are carried out by acomputer.

Oil Composition

One of the primary products of conventional fluid analysis is oilcomposition. There are two methods by which NMR can provide at least apartial composition analysis: spectroscopy and relaxation time analysis.

Spectroscopy: The NMR chemical shift depends on the molecularenvironment of a spin. Thus chemical conformation can be determined;this is one of the oldest and most widespread uses of nuclear magneticresonance. Crude oils are complex mixtures of hydrocarbons, and NMRspectroscopy is used to identify characteristic bands. For example,aliphatic protons appear in one frequency band, while aromatic protonsappear at another; both are distinguishable from water [H. J. Vinegar,U.S. Pat. No. 5,306,640 (1994)]. Chemical shift spectroscopy canperformed using either ¹H or ¹³C [Petrakis and Edelheit, AppliedSpectroscopy Reviews 15, 195 (1979); Botto, “fossil Fuels”, Encyclopediaof Nuclear Magnetic Resonance (1996)].

Relaxation Time Analysis: The relaxation time depends on correlationtimes due to molecular motion [Bloembergen, Purcell and Pound, PhysicalReview 73, 679 (1948)]. Protons in large molecules tend to move slower,and hence relax faster, than those in small molecules. Crude oils aremixtures of pure hydrocarbons, and have broad distributions ofrelaxation times [C. E. Morniss, R. Freedman, C. Straley, M. Johnston,H. J. Vinegar, P. N. Tutunjian, in Transactions of the SPWLA 35th AnnualLogging Symposium, 1994; Log Analyst, March-April 1997, pg 44]. Oil typeis determined by comparing relaxation time distributions obtained in thefluid sampling tool to a catalogue of such distributions compiled fromlaboratory data.

Water Phase Salinity

Determination of oil saturation from deep resistivity measurementsrequires knowledge of the water resistivity, R_(w). The presentresistivity measurement implemented in fluid sampling tools is alow-frequency current injection technique, which is unable to measureR_(w) in the presence of hydrocarbon.

It is possible to estimate R_(w) by measuring the concentration ofcurrent-carrying ions. Measuring individual concentrations of dissolvedions in the water phase is also very useful in interpreting flow linenuclear measurements of density and P_(e), the photoelectric absorptionfactor. The common ions in reservoir waters are [“Petroleum EngineeringHandbook”, H. B. Bradley, ed., Society of Petroleum Engineers, 1992,Chapter 24]:

cations: Ca, Mg, Na

anions: CO₃, HCO₃, SO₄, Cl

Among the cations, sodium often dominates, but there can be significantquantities of calcium and magnesium in some areas. Chlorine usuallydominates anion concentration, although there are some areas wherecarbonate, bicarbonate, or sulfate are important.

Solubility limits the combinations of ions that can be presentsimultaneously [CRC Handbook of Chemistry and Physics, pg B-73 et seq.].Note that solubilities can be modified by acidity, and depend ontemperature.

TABLE 1 Relatively soluble combinations Cation Anion Solubility (g/l)(hot water) Na Cl 391 Na CO₃ 455 Na SO₄ 425 Ca Cl 1590 Mg Cl 727 Mg SO₄738

TABLE 2 Relatively insoluble combinations Cation Anion Solubility (g/l)(hot water) Ca CO₃ 0.019 Ca SO₄ 0.162 Mg CO₃ 0.106

Thus high concentrations of calcium are incompatible with high levels ofcarbonate or sulfate, while high levels of magnesium are incompatiblewith high levels of carbonate. The magnesium sulfates (epsomite,kieserite) are not particularly common minerals, and magnesium andsulfate ion are rarely seen together at high concentrations [PetroleumEngineering Handbook, Chapter 24]. Thus measuring sodium and chloride,and applying the condition of charge neutrality, constrains thecomposition of oilfield waters. “Sodium waters” are those brines whichhave an excess of sodium over chloride:

[Na⁺]−[Cl⁻]=2([CO₃ ⁻⁻]+[SO₄ ⁻⁻]) for [Na⁺]−[Cl⁻]>0  (16)

“Chloride waters” are those brines which have an excess of chloride oversodium:

[Cl⁻]−[Na⁺]=2([Ca⁺⁺]+[Mg⁺⁺]) for [Cl⁻]−[Na⁺]>0  (17)

Thus total salinity (maximum of [Na⁺] and [Cl⁻]) and an estimate of ionidentity can be obtained, and used to estimate hydrogen index (seeabove), and water conductivity, density and Pe. The salinity is alsoimportant in estimating parameters for determination of density by gammaray scattering or X-ray scattering.

By changing the operating frequency of the NMR apparatus, the quantitiesof various isotopes can be determined. NMR properties of commonlyoccurring elements in oilfield fluids may be found in Table 3 below. Thebest isotopes for NMR measurements are ¹H, ²³Na and ³⁵Cl. The NMRamplitude of the sodium or chlorine resonance in an oil/water mixturewill give the volume of the water phase multiplied by the concentrationof the ion.

TABLE 3 NMR Properties of Elements Common in Oilfield Fluids FrequencyNatural NMR Net Isotope Frequency(¹H = 1) Abundance Sensitivity⁽¹⁾Sensitivity⁽²⁾ ¹H 1 1.00 1 1 ¹³C 0.251 0.011 1.59 × 10⁻² 1.75 × 10⁻⁴ ¹⁴N0.072 0.996 1.01 × 10⁻³ 1.01 × 10⁻³ ¹⁷O 0.136 3.7 × 10⁻⁴ 2.91 × 10⁻²1.08 × 10⁻⁵ ¹⁹F 0.941 1.00 0.83 0.83 ²³Na 0.264 1.00 9.25 × 10⁻² 9.25 ×10⁻² ²⁵Mg 0.061 0.101 2.67 × 10⁻³ 2.70 × 10⁻⁴ ³³S 0.076 0.0076 2.26 ×10⁻³ 1.72 × 10⁻⁵ ³⁵Cl 0.098 0.755 4.70 × 10⁻³ 3.55 × 10⁻³ ³⁷Cl 0.0820.245 2.71 × 10⁻³ 6.63 × 10⁻⁴ ³⁹K 0.047 0.931 5.08 × 10⁻⁴ 4.74 × 10⁻⁴⁽¹⁾At 100% abundance, ¹H = 1 ⁽²⁾At natural abundance, ¹H = 1

Sodium NMR: One expects ²³Na to have a much weaker NMR signal than ¹H,due to its lower NMR sensitivity and its lower concentration in aqueoussolution. For example, in a 0.057 Ω-m NaCl solution, [²³Na]=3 mol/Lwhereas [¹H]=111 mol/L, and one expects the ²³Na signal to be about 400times weaker than the ¹H signal. However, ²³Na, being a spin-{fraction(3/2)} nucleus, exhibits quadrupolar relaxation, which gives it a T₁ ofabout 50 ms. The relatively short T₁ aids in signal averaging, which canenhance SNR. For example, with a wait time of 250 ms, the ²³Na is fullypolarized (>99%), and signal averaging 4096 spin echoes resulted in a31.7 dB SNR. This reflects the echo peak amplitude compared to the rmsnoise level without any filtering or stacking of echoes in a singleCPMG. The measurement time in this example was 17 minutes, but filteringand stacking will reduce this time to about 1 minute. Further reductionsin measurement time can be realized through optimizing the wait time.Since sodium polarizes relatively quickly, good measurements can be madeat all flow rates currently in use in fluid sampling tools.

Chlorine NMR: Chlorine has two isotopes that can be observed with NMR,³⁷Cl and ³⁵Cl. Of the two, 35Cl is the preferred isotope to observebecause of its higher natural abundance (75.53%) and its higher NMRsensitivity (0.47% relative to 1H). Like ²³Na, ³⁵Cl is a spin-{fraction(3/2)} nucleus and exhibits quadrupolar relaxation with relaxation timesof a few milliseconds. Thus, ³⁵Cl is expected to fully polarize underany flow conditions, with relatively short wait times, which will allowfor rapid signal averaging.

Since other modifications and changes varied to fit particular operatingrequirements and environments will be apparent to those skilled in theart, the invention is not considered limited to the example chosen forpurposes of disclosure, and covers all changes and modifications whichdo not constitute departures from the true spirit and scope of thisinvention.

We claim:
 1. A method of analyzing fluid in a downhole environmentcomprising: a) introducing a fluid sampling tool into a well bore thattraverses an earth formation; b) using the fluid sampling tool toextract the fluid from the earth formation into a flow channel withinthe tool; c) monitoring an indication of contamination in the fluidwhile extracting the fluid from the earth formation and flowing thefluid through the flow channel; and d) when the indication ofcontamination in the fluid has stabilized, analyzing the fluid in theflow channel.
 2. The method of claim 1, wherein monitoring theindication of contamination comprises performing a magnetic resonancemeasurement on the fluid in the flow channel.
 3. The method of claim 1,wherein the indication of contamination comprises at least one of thefollowing: viscosity, relaxation time, composition, trace elementcontent, diffusion coefficient, proton density, signal amplitude,molecular conformation, and chemical shift.
 4. The method of claim 1,wherein analyzing the fluid in the flow channel comprises performing amagnetic resonance measurement on the fluid in the flow channel.
 5. Themethod of claim 1, wherein analyzing the fluid in the flow channelcomprises stopping the flow of fluid in the flow channel whileperforming the magnetic resonance measurement.
 6. The method of claim 1,wherein analyzing the fluid in the flow channel comprises slowing theflow of the fluid in the flow channel while performing the magneticresonance measurement.
 7. The method of claim 1, wherein analyzing thefluid in the flow channel comprises continuing the flow of the fluid inthe flow channel while performing the magnetic resonance measurement. 8.The method of claim 1, wherein analyzing the fluid in the flow channelcomprises determining at least one of the following: fluid volume,diffusion coefficient, relaxation time, proton chemical shift,hydrogen/carbon ratio, viscosity, stock tank API gravity, and fluidcomposition.
 9. A method of analyzing hydrocarbon in a fluid in adownhole environment comprising: a) introducing a fluid sampling toolinto a well bore that traverses an earth formation; b) using the fluidsampling tool to extract fluid from the earth formation into a flowchannel within the tool; c) applying a static magnetic field to thefluid in the flow channel; d) applying an oscillating magnetic field ata frequency sensitive to carbon-13 nuclei to the fluid in the flowchannel; e) detecting magnetic resonance signals indicative of carbon-13nuclei from the fluid; and f) analyzing the detected magnetic resonancesignals to extract information about hydrocarbon in the fluid.
 10. Themethod of claim 9, further comprising stopping the flow of the fluidthrough the flow channel prior to performing steps (c)-(e).
 11. Themethod of claim 9, wherein the oscillating magnetic field comprises aseries of oscillating magnetic field pulses.
 12. The method of claim 9,further comprising applying a second oscillating magnetic field at afrequency sensitive to hydrogen nuclei to the fluid in the flow channel.13. The method of claim 12, wherein analyzing the detected magneticresonance signals comprises decoupling the second oscillating magneticfield from the detected signals.
 14. The method of claim 9, furthercomprising applying a second oscillating magnetic field at a frequencysensitive to hydrogen-1 nuclei to the fluid in the flow channel anddetecting magnetic resonance signals indicative of hydrogen-1 nucleifrom the fluid.
 15. The method of claim 14, wherein analyzing thedetected magnetic resonance signals comprises calculating ahydrogen/carbon ratio.
 16. The method of claim 9, wherein analyzing thedetected magnetic resonance signals comprises estimating hydrocarbonquantity in the fluid.
 17. A method of analyzing water phase fluid in adownhole environment comprising: a) introducing a fluid sampling toolinto a well bore that traverses an earth formation; b) using the fluidsampling tool to extract fluid from the earth formation into a flowchannel within the tool; c) applying a static magnetic field to thefluid in the flow channel; d) applying an oscillating magnetic field tothe fluid in the flow channel; e) detecting magnetic resonance signalsindicative of nuclei of at least one of the following from the fluid:sodium-23, chlorine-35, chlorine-37, and potassium-39; and f) analyzingthe detected magnetic resonance signals to determine information aboutthe water phase fluid.
 18. The method of claim 17, further comprisingflowing the fluid through the flow channel and performing steps (c)-(e)while the fluid is flowing.
 19. The method of claim 17, wherein thedetected magnetic resonance signals are analyzed to determine salinityof the fluid.
 20. The method of claim 19, further comprising analyzingthe detected magnetic resonance signals to determine water phaseresistivity.
 21. A method of determining stock tank API gravity of acrude oil sample from downhole fluid analysis comprising: a) introducinga fluid sampling tool into a well bore that traverses an earthformation; b) using the fluid sampling tool to extract the crude oilsample from the earth formation; c) measuring a downhole temperature ofthe crude oil sample; d) determining a downhole viscosity of the crudeoil sample; e) determining a downhole gas/oil ratio of the crude oilsample; and f) correlating the dowhole temperature, viscosity andgas/oil ratio with the stock tank API gravity of the crude oil sample.22. The method of claim 21, wherein determining the downhole viscosityof the crude oil sample comprises: i) applying a static magnetic fieldto the crude oil sample; ii) applying a sequence of oscillating magneticfield pulses to the crude oil sample; iii) detecting magnetic resonancesignals from the crude oil sample; iv) determining a relaxation timeassociated with the crude oil sample; and v) relating the relaxationtime to the downhole viscosity of the crude oil sample.
 23. The methodof claim 22, wherein determining a relaxation time comprises performinga relaxation time analysis on the detected magnetic resonance signals.24. The method of claim 22, wherein determining a relaxation timecomprises performing a chemical shift analysis on the detected magneticresonance signals.
 25. The method of claim 21, wherein determining thedownhole gas/oil ratio of the crude oil sample comprises: i)transmitting near-infrared light through the crude oil sample; ii)measuring optical absorption at a first wavelength at which gas absorbsnear-infrared light; iii) measuring optical absorption at a secondwavelength at which oil absorbs near-infrared light; and iv) calculatingthe downhole gas/oil ratio based on the optical absorptions at the firstand second wavelengths.
 26. A nuclear magnetic resonance module adaptedfor incorporation into a fluid sampling tool comprising: a permanentmagnet array adapted to be arranged around a flow line in the fluidsampling tool, wherein the tool includes means for extracting fluid froman earth formation; a nuclear magnetic resonance antenna adapted to bearranged around the flow line; means coupled with the antenna forgenerating an oscillating magnetic field within the flow line; and meanscoupled with the antenna for detecting nuclear magnetic resonancesignals from the flow line.
 27. The nuclear magnetic resonance module ofclaim 26, wherein the means for generating an oscillating magnetic fieldcomprises means for generating a sequence of oscillating magnetic fieldpulses.
 28. The nuclear magnetic resonance module of claim 26, whereinthe means for generating an oscillating magnetic field comprises meansfor varying the frequency of the oscillating magnetic field.
 29. Thenuclear magnetic resonance module of claim 28, wherein the means fordetecting nuclear magnetic resonance signals comprises means fordetecting nuclear magnetic resonance signals from more than one type ofnucleus.